Methods and apparatus for multi dimension fluorescence spectrum measurement and correlations downhole

ABSTRACT

Some principles described herein contemplate implementation of downhole imaging for the characterization of formation fluid samples in situ, as well as during flow through production tubing, including subsea flow lines, for short term investigation, permanent, and/or long term installations. Various methods and apparatus described herein may facilitate downhole testing. For example, some embodiments facilitate multi-dimensional fluorescence spectrum measurement testing downhole and correlating the fluorescence with other oil properties.

FIELD

The present disclosure relates generally to methods and systems forinvestigating subterranean formation fluids. More particularly, someaspects of this disclosure are directed to methods and systems forspectral imaging to characterize downhole fluids.

BACKGROUND

Fluid characterization is very important to the assessment of economicviability for a hydrocarbon-bearing reservoir formation. Some wirelinetools such as Schlumberger's MDT (Modular Dynamic Tester) are used tosample formation fluids, store it in a set of bottles, and retrieve itto surface while keeping the fluid pressurized. Such samples are knownas live fluids. These live fluids are then sent to an appropriatelaboratory to be characterized. Characterization of the fluids mayinclude composition analysis, fluid properties and phase behavior.

Understanding reservoir fluid phase behavior is key to proper planningand development of the respective fields and design of the productionsystem. Understanding reservoir fluid phase behavior involves conductinga number of very important measurements on the fluid at realisticreservoir and production conditions. In most cases, changes intemperature (T) and pressure (P) of the formation fluid lead to phasechanges, including phase separation (e.g., liquid-vapor, liquid-solid,liquid-liquid, vapor-liquid etc.), and phase recombination. For example,while most hydrocarbons exist as a single phase at initial reservoirconditions (i.e., composition, pressure, and temperature), they oftenundergo reversible (and possibly some irreversible) multi-phase changesdue to pressure, composition and/or temperature reduction duringproduction and flow to the surface facilities.

Liquid-Solid-Vapor phase boundaries are typically measured at alaboratory using state-of-the-art-technologies, such as Schlumberger'spressure-volume-temperature (PVT) unit coupled to Schlumberger'slaser-based Solids Detection System (SDS) and Schlumberger'shigh-pressure microscope (HPM). Detailed descriptions of thesestate-of-the art technologies and their applications for the study ofphase behavior and flow assurance of petroleum fluids have beenpublished and are known to those of skill in the art.

However, the one trend in the industry is to perform more and moreanalysis of the formation and the formation fluid properties directlydownhole to avoid the difficulties associated with sample preservationwhen lifted uphole and delays associated with sample transportation andanalysis in a remote laboratory. Tools like Schlumberger's MDT can, forexample, be retrofitted with a spectrometer module such as a Live FluidAnalyser or Gas Condensate Analyser in order to provide basicinformation on the fluid composition (Gas-to-oil ratio (GOR), watercontent, basic crackdown of hydrocarbon fractions (C₁, C₂-C₅, C₆+)).These measurements are performed by infrared (IR) absorptionspectroscopy.

Nevertheless, current measurements of certain downhole characteristicsdo not facilitate full analysis of the formation and fluids, especiallyin situ. Fluorescence measurements downhole as discussed herein may beused to more fully characterize formations and formation fluids. Inaddition, U.S. Patent Application Publication Number 2004/0000636assigned to Schlumberger Technology Corporation and invented by OliverMullins et al. discusses determining dew precipitation onset pressure ina sample located downhole in an oilfield reservoir, which may includemeasuring 1D fluorescence.

Further, while there has been some use of video imaging downhole inwireline tools, current technology is generally limited to applicationsrelated to production logging. Most current downhole imaging isdedicated to borehole wall imaging and has low spatial resolution(although commonly-owned U.S. patent application Ser. No. 11/204,134discusses additional imaging capability). DHV International, forexample, provides downhole video services to the oil and gas industryfor diagnosis of borehole problems such as fishing out lost tools,mechanical inspection, and fluid entry surveys. There is room to improvemethods and systems to more fully characterize formation fluidsdownhole.

SUMMARY

The present specification may meet the above-described needs and others.In one embodiment, the present disclosure provides a method comprisingproviding a downhole testing tool, deploying the downhole testing toolinto a borehole, and performing a multi-dimensional fluorescencespectrum measurement downhole. In this, the disclosure hereincontemplates applications in wireline tools, drilling and measuringtools, permanent monitoring, production logging, among others, withdeployment modes that include conventional wireline and drillingsystems, and slickline, coiled tubing, clamping devices, etc.

In one embodiment, two of the multi-dimensional fluorescence spectrummeasurements comprise wavelength of excitation light and fluorescencespectrum. In one embodiment, two of the multi-dimensional fluorescencespectrum measurements comprise fluorescence relaxation time andfluorescence spectrum. In one embodiment, performing themulti-dimensional fluorescence spectrum measurement comprises twodimensional fluorescence imaging with a charged-coupled device (CCD) ora complementary metal oxide semiconductor (CMOS) camera. The method mayinclude communicating the multi-dimensional fluorescence spectrummeasurement uphole. One embodiment of the method comprises performingthe multi-dimensional fluorescence spectrum measurement downhole atmultiple boreholes, comparing the multi-dimensional fluorescencespectrum measurements at the multiple boreholes, and determiningconnectivity between the multiple boreholes based on the comparing ofthe multi-dimensional fluorescence spectrum measurements. In oneembodiment, the downhole testing tool further comprises apressure-volume control unit. Some embodiments of the downhole testingtool comprise a portion of a wireline tool. In one embodiment, thedownhole testing tool is permanently installed downhole and in fluidcommunication with a production line. Some embodiments further compriseperforming a multi-dimensional fluorescence spectrum measurement in alab on a same fluid measured downhole, and comparing themulti-dimensional fluorescence spectrum measurement of the lab withmulti-dimensional fluorescence spectrum measurement performed downhole.The comparison may be used to establish a clean chain of custody.

One aspect provides a method of identifying subterranean fluids. Thesubterranean or downhole fluids may be formation fluids, drilling muds,or other fluids. The method comprises characterizing a formation fluidsample downhole according to multi-dimensional fluorescence spectrummeasurements. In one embodiment, two of the multi-dimensionalfluorescence spectrum measurements comprise wavelength of excitationlight and fluorescence spectrum. In another embodiment, two of themulti-dimensional fluorescence spectrum measurements comprisefluorescence relaxation time and fluorescence spectrum. In anotherembodiment, performing the multi-dimensional fluorescence spectrummeasurement comprises two dimensional fluorescence imaging with acharged-coupled device (CCD) or a complementary metal oxidesemiconductor (CMOS) camera. In one embodiment, a light source and thecamera comprise a transmission imaging configuration. In one embodiment,a light source, a reflector, and a camera comprise a back-scatteredimaging configuration.

One aspect provides a method of identifying subterranean formationfluids, comprising providing a downhole testing tool having an opticalfluid analyzer, deploying the downhole testing tool into a borehole,exciting an energy state of the formation fluids adjacent to the opticalfluid analyzer above a ground state, measuring fluorescence lightemitted by the formation fluids in a relaxation process from an excitedstate to the ground state, and plotting fluorescence spectra as afunction of time. One embodiment further comprises comparing plots offluorescence spectra as a function of time with samples from variousboreholes. One embodiment further comprises comparing plots offluorescence spectra as a function of time with samples of knownproperties. One embodiment further comprises comparing plots offluorescence spectra as a function of time with samples from variousboreholes, and determining similarities between the plots of the samplesfrom the various boreholes to anticipate well connectivity.

One embodiment provides a downhole apparatus. The downhole apparatuscomprises a downhole lab module. The downhole lab module comprises asample flow line, a sample cell in fluid communication with the sampleflow line, the sample cell comprising at least one transparent window, alight source adjacent to the sample cell, a spectrometer for detectingfluorescence, and a set of instructions, that, when executed, performmulti-dimensional fluorescence spectrum measurements downhole. Oneembodiment further comprises a set of instructions that, when executed,excite an energy state of the formation fluids adjacent to the opticalfluid analyzer above a ground state, measure fluorescence light emittedby the formation fluids in a relaxation process from an excited state tothe ground state, and plot fluorescence spectra as a function of time.One embodiment further comprises a set of instructions that, whenexecuted, excite an energy state of the formation fluids adjacent to theoptical fluid analyzer above a ground state, measure fluorescence lightemitted by the formation fluids in a relaxation process from an excitedstate to the ground state, and plot wavelength of excitation lightversus fluorescence spectrum. One embodiment further comprises a cameracapable of 2D fluorescence imaging of formations downhole.

One embodiment provides a downhole apparatus comprising a downhole labmodule, the downhole lab module comprising a cell having an opticalwindow in contact with a downhole formation, a light source adjacent tothe cell, a spectrometer for detecting fluorescence emitted from theformation, and a set of instructions, that, when executed, performmulti-dimensional fluorescence spectrum measurements downhole of theformation.

One aspect provides a method comprising downhole fluid mapping. Thedownhole fluid mapping comprises providing a downhole testing tool,deploying the testing tool into a borehole, measuring fluorescencedownhole, and correlating fluorescence measurements with oil properties.In one embodiment, downhole fluid mapping occurs in the presence ofemulsions. The correlating may comprise plotting wave-number versusfluorescence intensity. In one embodiment, the method comprisesgenerating a correlation function based on the plot. In one embodiment,the method comprises matching the correlation function to a correlationfunction for a known oil. In one embodiment, the fluorescencemeasurements comprise 2D fluorescence measurements. The fluorescencemeasurements may comprise a 2D fluorescence map, and the method mayfurther comprise slicing the 2D fluorescence map at different energylevels to find a correlation between fluorescence and oil properties.

According to one embodiment, the correlating comprises plottingasphaltenes and/or resins weight fraction versus fluorescence intensity.The method may comprise generating a correlation function based on theplot. The method may further comprise matching the correlation functionto a known oil.

In one embodiment, the correlating comprises plotting C36+ contentversus fluorescence intensity, generating a correlation function basedon the plot, and matching the correlation function to a known oil.

Another aspect provides a method of downhole fluid mapping. The downholefluid mapping comprises providing a downhole testing tool, deploying thetesting tool into a borehole, measuring 2D fluorescence downhole,plotting wave-number versus fluorescence intensity, plotting asphaltenesand/or resins weight fraction versus fluorescence intensity, plottingC36+ content versus fluorescence intensity, generating correlationfunctions based on the plots, and matching the correlation functions toa known oil. In one embodiment, the 2D fluorescence measurementscomprise a 2D fluorescence map, and the method further comprises slicingthe 2D fluorescence map at different energy levels to find strongercorrelation functions.

One method comprises fingerprinting oils from a particular basin. Thefingerprinting comprises taking 2D fluorescence measurements downhole,plotting the 2D fluorescence measurements versus at least one oilproperty, and generating a correlation function between the 2Dfluorescence measurements and at least one oil property. The method mayfurther comprise generating 2D fluorescence contour plots. The at leastone oil property may comprise a plurality of oil properties. In oneembodiment, the plurality of oil properties comprises wave number,asphaltenes and/or resin weight fraction, and C36+ content.

One embodiment provides a downhole apparatus. The downhole apparatuscomprises a downhole lab module, the downhole lab module comprising asample flow line, a sample cell in fluid communication with the sampleflow line, the sample cell comprising at least one optical ortransparent window, a light source adjacent to the sample cell, aspectrometer for detecting fluorescence, and a set of instructions,that, when executed, perform multi-dimensional fluorescence spectrummeasurements downhole and correlate fluorescence measurements with oilproperties. In one embodiment, the light source illuminates an emulsion.In one embodiment, the downhole apparatus further comprises a set ofinstructions that, when executed, excite an energy state of theformation fluids adjacent to the optical fluid analyzer above a groundstate, measure the fluorescence emitted by the formation fluids in arelaxation process from an excited state to the ground state, and plotfluorescence spectra as a function of time.

Additional advantages and novel features will be set forth in thedescription which follows or may be learned by those skilled in the artthrough reading these materials or practicing the principles describedherein. Some of the advantages described herein may be achieved throughthe means recited in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings illustrate certain embodiments and are a partof the specification. Together with the following description, thedrawings demonstrate and explain some of the principles of the presentinvention.

FIG. 1 is a fluorescence spectrum of various crude oils. In the diagramof FIG. 1, a 470 nm LED is used for excitation light.

FIG. 2 is a cut-away cross-sectional view of a composition fluidanalyzer (CFA) fluorescence detector according to one embodiment.

FIG. 3A is a fluorescence spectrum of oil at different excitations oflight according to one embodiment.

FIG. 3B is a contour plot of the fluorescence spectra shown in FIG. 3A.

FIG. 4A illustrates a contour plot of an actual oil sample fluorescencespectra for a dead crude oil generated in a lab according to the priorart.

FIG. 4B illustrates a contour plot of an actual oil sample fluorescencespectra for another dead crude oil generated in a lab according to theprior art.

FIGS. 5A-5C illustrate a 2D fluorescence measurement concept of spectrumvs. relaxation time according to one embodiment.

FIG. 6A is a schematic diagram showing an optical layout of a downholeflow line imaging apparatus. FIG. 6A illustrates a transmissionconfiguration.

FIG. 6B is another schematic diagram showing an optical layout of adownhole flow line imaging apparatus. FIG. 6B illustrates a backscatterconfiguration.

FIG. 7A is a schematic optical layout for optical fluorescentmeasurement in a flow line according to one embodiment. FIG. 7Aillustrates a transmission layout.

FIG. 7B is a schematic optical layout for optical fluorescentmeasurement of a formation fluid according to another embodiment. FIG.7B illustrates a reflection layout.

FIG. 7C is a schematic optical layout for optical fluorescentmeasurement of a formation fluid according to another embodiment. FIG.7C illustrates a fiber bundle layout.

FIG. 8A is a schematic of an apparatus for downhole optical fluorescentmeasurement at a formation surface according to one embodiment.

FIG. 8B is a magnified detail schematic of the apparatus of FIG. 8A.

FIG. 9A is another schematic diagram showing an optical layout of adownhole flow line fluorescence detection apparatus utilizing a tunableor pulsed light source.

FIG. 9B illustrates a plot of fluorescence intensity or relaxation as afunction of time according to use of the apparatus of FIG. 9A.

FIG. 9C illustrates a plot of light source intensity as a function oftime when an optical filter is used with the apparatus of FIG. 9A.

FIG. 9D illustrates a light pulse for the light source of FIG. 9Aaccording to one embodiment.

FIG. 10 is a chart illustrating a correlation between absorption cut-off(wave-number) and fluorescence intensity (area) for twenty nine deadoils.

FIG. 11 is a chart illustrating a correlation of absorption andfluorescence with asphaltenes and/or resin weight fraction (for twentynine dead oils).

FIG. 12 is a chart illustrating a correlation of absorption andfluorescence with C36+ content (for twenty nine dead oils).

FIG. 13 illustrates 2D fluorescence of twenty-nine dead oils from manydifferent basins ranked (left to right, top to bottom) according totheir asphaltenes+resin weight fraction from SARA analysis.

FIG. 14 illustrates a correlation between fluorescence andasphaltenes+resin weight fraction for six oils from a similar region inthe Middle East. Slicing 2D fluorescence map at different energiesreveals that correlation is higher for 325 nm excitation than 470 nm.

Throughout the drawings, identical reference numbers and descriptionsindicate similar, but not necessarily identical elements. While theprinciples described herein are susceptible to various modifications andalternative forms, specific embodiments have been shown by way ofexample in the drawings and will be described in detail herein. However,it should be understood that the invention is not intended to be limitedto the particular forms disclosed. Rather, the invention includes allmodifications, equivalents and alternatives falling within the scope ofthe appended claims

DETAILED DESCRIPTION

Illustrative embodiments and aspects of the invention are describedbelow. It will of course be appreciated that in the development of anysuch actual embodiment, numerous implementation-specific decisions mustbe made to achieve the developers' specific goals, such as compliancewith system-related and business-related constraints, that will varyfrom one implementation to another. Moreover, it will be appreciatedthat such a development effort might be complex and time-consuming, butwould nevertheless be a routine undertaking for those of ordinary skillin the art having the benefit of this disclosure.

Reference throughout the specification to “one embodiment,” “anembodiment,” “some embodiments,” “one aspect,” “an aspect,” or “someaspects” means that a particular feature, structure, method, orcharacteristic described in connection with the embodiment or aspect isincluded in at least one embodiment of the present invention. Thus, theappearance of the phrases “in one embodiment” or “in an embodiment” or“in some embodiments” in various places throughout the specification arenot necessarily all referring to the same embodiment. Furthermore, theparticular features, structures, methods, or characteristics may becombined in any suitable manner in one or more embodiments. The words“including” and “having” shall have the same meaning as the word“comprising.”

Moreover, inventive aspects lie in less than all features of a singledisclosed embodiment. Thus, the claims following the DetailedDescription are hereby expressly incorporated into this DetailedDescription, with each claim standing on its own as a separateembodiment of this invention.

A fluorescence (FL) spectrum reflects energy structure that isdetermined by bonds between atoms in a molecule. Fluorescencemeasurement is often used in the chemical analysis field. In order toobserve a fluorescence spectrum, an energy state excitation isnecessary. Fluorescence light is emitted during the relaxation processfrom an excitation state to a ground state.

FIG. 1 shows fluorescence spectra of various crude oils labeled A-E. Thelarge, truncated peak in FIG. 1 represents excitation light that happensto be 470 nm blue LED light. The broader peaks A-E in the 500-600 nmwavelength regions represent fluorescence signals. As illustrated inFIG. 1, different crude oil samples have different spectral shapes atthe longer wavelength ranges (as opposed to the nearly identical peakshapes at the excitation light wavelength). However, it is currentlydifficult to obtain much useful or detailed information about the crudeoils based on the fluorescence spectra alone because of the simplicityof the shapes associated with the fluorescence spectra that are excitedby certain excitation light sources.

CFAs have been implemented for fluorescence measurement, but theexcitation wavelength is typically a single wavelength and only twoemission wavelengths are currently detected. FIG. 2 is a schematicdrawing of one fluorescence detector 100 that may be part of a downholetool (e.g. a downhole wireline tool) that may be used to makefluorescence measurements. The fluorescence detector 100 includes alight source, for example a 470 nm LED light source 102. Thefluorescence detector 100 may also include two fluorescence detectionchannels FL#0 and FL#1 that have different cutoff optical filters 104.The fluorescence detector 100 may also include a reflected lightdetection channel 106. The channels FL#0, FL#1, and reflected lightdetection channel 106 may be arranged in an optical prism such as asapphire prism 108. Each channel (FL#0, FL#1, and reflected lightdetection channel 106) may include an optical rod such as a glass rod110 to direct light from an optical window 112 adjacent a sample 114.

In the embodiment of FIG. 2, fluorescence detection channels FL#0 andFL#1 of a downhole testing tool may have λ₁ and λ₂ cutoff wavelengthoptical filters 104, respectively. However, other optical filters mayalso be used, including additional detection channels. The fluorescencedetection channels FL#0 and FL#1 may be used to observe rough spectrumshapes (such as the ones shown in FIG. 1). In one embodiment, the firstfluorescence detection channel FL#0 integrates intensity of fluorescencespectrum from λ₁ and longer, and the second fluorescence detectionchannel FL#1 integrates intensity of fluorescence above λ₂. Theintensity of the light reflected at an interface 116 between bottomwindow 112 and a flow line 116 carrying the sample 114 depends on therefractive index of the sample 114 in the flow line 116. However,approximately 100% of the light (represented by arrows 118) from the λemission LED light source 102 is reflected when air flows in the flowline 116 adjacent the window 112. Less than 100% of the light from the λLED light source 102 is reflected if fluid flows through flow line 116.

As mentioned above, fluorescence spectroscopy (1D or one dimension) hasbeen used to get general—but not detailed—information about formationfluids and other downhole fluids (e.g. drilling muds) based on thespectral shapes measured. However, according to some embodiments, morethan 1D fluorescence spectroscopy, for example at least 2D fluorescencemeasurements, may be taken to further characterize formations, downholefluids, formation fluids, etc. (and such measurements andcharacterization may be done downhole or in situ). Mud itself does notexhibit fluorescence. Therefore, finding fluorescence in a mud fluid mayindicate that oil-bearing formations have been reached.

In one embodiment illustrated in FIGS. 3A-3B, a 2D measurement ofspectrum vs. wavelength of excitation light is shown. FIG. 3Aillustrates fluorescence spectra for different excitation light sources.Sharp peaks 120 in shorter wavelength locations again represent spectraof excitation light. Broader peaks 122 at the longer wavelengthsrepresent fluorescence spectra for the sample (e.g. oil). In one aspect,many fluorescence spectra may be measured with many kinds of excitationlight to generate a 2D fluorescence spectrum contour plot such as theone shown in FIG. 3B. FIGS. 4A-4B represent 2D fluorescence measurementdata or contour plots from actual dead crude oils that were generated inan uphole lab according to the prior art. FIG. 4A is a 2D spectrum ofSahara crude oil, and FIG. 4B is a 2D spectrum of Nigeria light crudeoil. As shown in FIGS. 4A-4B, different samples (such as different oils)exhibit different fluorescence spectrum in uphole labs. In particular,FIGS. 4A-4B illustrate contour plots of dead oil from a tanker spill.Fujita, M., “Analysis and Identification of Spilled Oil in Ocean,” JAPANENVIRONMENTAL MEASUREMENT & CHEMICAL ANALYSIS, Vol. 19, No. 4, 1990(rough translation of titles from Japanese). As understood by those ofordinary skill in the art having the benefit of this disclosure, a deadoil is one that is no longer pressurized but has been subjected toatmospheric pressure. Further, one of ordinary skill in the art havingthe benefit of this disclosure will understand that the volatilefraction of a dead oil will have evaporated from the liquid phase.However, according to principles described herein, different 2Dfluorescence spectra are generated downhole, and can be compared toknown measurements to identify or characterize the samples downhole.Fluorescence may be of particular interest for the characterization ofthe aromatic fraction of oil. Part of the aromatic compounds can bequite volatile under atmospheric pressure conditions. With the directimplementation downhole according to principles described herein, thearomatic fraction of a live oil is characterized downhole in oneembodiment and would otherwise be lost if the sample was depressurized(as with a tanker spill).

Other at least 2D fluorescence measurements may also be used tocharacterize samples. For example, FIGS. 5A-5C illustrate 2Dfluorescence measurements of a spectrum as a function of relaxationtime. Generally, fluorescence “relaxes” over time and fluorescentintensity decreases exponentially with time. FIG. 5A illustrates atypical fluorescence intensity plot over time. Moreover, thefluorescence spectrum shape changes over time. FIG. 5B representsdifferent fluorescence spectra at each of four different times (T1, T2,T3, and T4). The changes in fluorescence spectra over time arecharacteristic of particular sample compositions that can be recordedand compared to the same criteria of known samples. Thus, the 2Dfluorescence spectrum including fluorescence spectrum and the relaxationtime axes shows the relaxation process from an excited energy state andis identifiable for different samples. FIG. 5C is a 2D fluorescencespectrum plot showing fluorescence spectrum as a function of relaxationtime. The relaxation spectra in the 2D plot of FIG. 5C illustrates arelaxation process that includes features that may be unique to samplecompositions (such as different crude oils).

In addition to or separate from using 2D fluorescence measurements toidentify samples, some aspect may simply “fingerprint” samples. Forexample, in one aspect, 2D fluorescence measurements are taken for afirst downhole sample in a first borehole. Another set of 2Dfluorescence measurements may be taken for a second sample in a secondborehole. The 2D fluorescence measurements or “fingerprint” of the firstsample may be compared to the “fingerprint” of the second sample toevaluate formation connectivity. For example, if a 2D fluorescencespectrum of crude oil in one formation indicates the same 2Dfluorescence spectrum in another formation, it is likely that theformations are connected somewhere.

Further, in addition to the two different 2D fluorescence measurementsthat may be taken, for example, downhole by a downhole tool and relayeduphole, other imaging downhole is also contemplated. FIGS. 6A and 6Billustrate optical layouts of downhole tools having flow line imagingcapability according to some embodiments. FIG. 6A is a transmissionconfiguration wherein light from a light source 130 or fluorescence froma sample in a flow line 128 is imaged by a camera 132 (which may be aCCD (charged coupled device), a CMOS (complementary metal oxidesemiconductor) camera, or other camera). In the embodiment of FIG. 6A,the light source 130 and the camera 132 are placed on opposite sides ofa flow line sample cell 134 having windows 136. The sample cell 134 isfluidly connected to the flow line 128. The sample cell 134 comprisesthe one or more window 136 shown in FIG. 6A. The windows 136 comprise amaterial that is at least partially transparent to light. The windows136 may be made, for example, of sapphire. Many possible configurationsof the light source 130 and camera 132 are contemplated herein. Twopossible configurations are shown in FIGS. 6A-6B. In one embodiment thecamera 132 is a spectral camera. The camera 132 can provide spectralinformation in function of pixels. A backscatter configuration shown anddescribed below in connection with FIG. 6B may provide the samemeasurements as those described above, but with spatial resolutioninstead of averaging it within sample volume.

In a backscatter imaging configuration as shown in FIG. 6B, the lightsource 130 and the camera 132 may both be arranged on the same side of asample cell 234. The sample cell 234 may thus include only one window136. A beam splitter 138, which is shown as a tilted plate between thesample cell 234 and the camera 132, is used to direct light to thesample cell 234 while also allowing backscattered light to return to thecamera 132. Accordingly, direct electromagnetic radiation from the lightsource 130 is directed to the window 136 by the beam splitter 138, andradiation may be reflected from the sample and detected by the camera132. Reflected light may also be due to light reemitted by the sample inthe flow line 128 itself because of fluorescence.

FIG. 7A illustrates an embodiment wherein a wavelength selectable lightsource 230 for excitation is arranged on one side of a sample flow line128 and a lens 240 is arranged between the sample flow line 128 and aspectrometer 232 opposite of the light source 230. FIGS. 7A-7Cillustrate several possible apparatuses that may be used for the 2D FLmeasurement. FIG. 7A illustrates a measurement in a transmissionconfiguration. FIGS. 7B and 7C illustrate mechanisms for measurement inreflection configurations. In FIG. 7A, the excitation light is providedby light source 230, transmitted through the sample 128, and throughoptical windows 136. A lens system 240 collects the light transmittedthrough the optical cell 134 and transmits it to the spectrometer 232.In FIG. 7B, the scheme is the same but the analyzed light is onereflected from the cell via window 236. In FIG. 7C, instead of using alens system to guide the light, an optical fiber 242 is used.

According to some aspects, fluorescence imaging may be used todiscriminate between oil-bearing formations and other formations. Forexample, limestone containing oil will emit fluorescent light followingexcitation, which can be viewed by a camera, while other formations thatdo not bear hydrocarbons will tend not to emit any fluorescence. Some ofthe embodiments that may be used to image fluorescence downhole and helpdetermine which formations contain hydrocarbons are depicted in FIGS.7B-7C.

FIG. 7B schematically illustrates an apparatus wherein the sample 128 isa formation fluid sample. An optical window 236 may be directly adjacentto or even attached to the formation of interest. A light source such asthe wavelength selectable light source 230 emits light through theoptical window 236 at an angle and excites the formation fluid 128and/or any oil in the formation fluid 128. If there is oil in theformation fluid 128, fluorescent light is emitted as the oil relaxesfrom the excited state. Fluorescence (if any) is directed back throughthe optical window toward a camera or spectrometer 232 where it isdetected or imaged. A lens 240 may focus fluorescence to thespectrometer 232. Accordingly, fluorescence may be viewed or detecteduphole via the downhole system illustrated in FIG. 7B to help determinewhether formations of interest are hydrocarbon-bearing. In some aspectsthe downhole system illustrated in FIG. 7B may be used to also determinethe composition of any hydrocarbons.

FIG. 7C schematically illustrates another downhole apparatus wherein thesample 128 is a formation fluid. According to the embodiment of FIG. 7C,the optical window 136 is adjacent to or attached to the formation andalso coupled to fiber optic bundles 242 and 244. The first fiber opticbundle 242 is optically coupled between the wavelength selectable lightsource 230 and the optical window 136. The light source 230 emits lightthrough the optical window 136 via the first fiber optic bundle 242 andexcites the formation fluid 128 and/or any oil in the formation fluid128. If there is oil in the formation fluid 128, fluorescent light isemitted as the oil relaxes from the excited state. Fluorescence (if any)is directed back through the optical window and to the camera orspectrometer 232 via the second fiber optic bundle 244 where it isdetected or imaged. Again, fluorescence may be viewed or detected upholevia the downhole system illustrated in FIG. 7C to help determine whetherformations of interest are hydrocarbon-bearing. Other configurationsincluding a downhole excitation source and a downhole detector may alsobe used.

Accordingly, in one aspect a method may be implemented which includesproviding a downhole testing tool, deploying the downhole testing toolinto a borehole, and performing a multi-dimensional fluorescencespectrum measurement downhole. In one aspect two of themulti-dimensional fluorescence spectrum measurements comprise wavelengthof excitation light and fluorescence spectrum. Performing themulti-dimensional fluorescence spectrum measurement may compriseplotting wavelength of excitation light versus fluorescence spectrum.

In one aspect, two of the multi-dimensional fluorescence spectrummeasurements comprise fluorescence relaxation time and fluorescencespectrum. Performing a multi-dimensional fluorescence spectrummeasurement may comprise plotting fluorescence relaxation time versusfluorescence spectrum. In one aspect, performing the multi-dimensionalfluorescence spectrum measurement comprises two dimensional fluorescenceimaging with a charged-coupled device (CCD) or a complementary metaloxide semiconductor (CMOS) camera.

In one aspect, the method includes communicating the multi-dimensionalfluorescence spectrum measurements uphole. The methods may includeperforming multi-dimensional fluorescence spectrum measurements downholeat multiple boreholes, comparing the multi-dimensional fluorescencespectrum measurements at the multiple boreholes, and determiningconnectivity between the multiple boreholes based on the comparing ofthe multi-dimensional fluorescence spectrum measurements. Moreover, inone embodiment the downhole testing tool (which may be a wireline tool)shown in part in FIGS. 2 and 6A-7A further comprises a pressure-volumecontrol unit. Further, in one embodiment the downhole testing tool ispermanently installed downhole and in fluid communication with aproduction line.

Turning now to FIGS. 8A-8B, another configuration that may be used for2D fluorescent imaging is shown. According to the embodiment of FIGS.8A-8B, a downhole tool 800 may include an extendable pad 802 enablingcharacterization of fluids 806 at a formation surface 804. The pad 802may be pushed or pumped out to remove the mud cake and establish opticalcontact with the surface 804 of the formation 808. A window 810interfaces between the formation 808 and the inside of the downhole tool800 (which may be fluorescence measurement capable as described above).Light sources 812 excite the formation 808 and any fluids or oils 806 atthe surface 804. A spectral camera 814 behind the window 810 performsthe imaging, such as fluorescence imaging, and facilitates fluidcharacterization in accordance with principles described above.

FIGS. 9A-9D illustrate apparatus and plots associated with someembodiments. Referring to FIG. 9A, one apparatus that may be used tomeasure fluorescence downhole is shown. Similar to the embodiment ofFIGS. 6A-6B, FIG. 9A illustrates a schematic optical layout of adownhole tool having flow line imaging capability. FIG. 9A fluorescenceacquisition is collected by a spectrometer 332. Excitation light 335from a light source 330 excites a sample 328 in a flow line 334 throughan optical window 336. In the imaging configuration shown in FIG. 9A,the light source 330 and the spectrometer 332 may both be arranged onthe same side of the optical window 336. Fluorescent light 337 resultingfrom the excitation light 335 is emitted from the sample 328 anddetected by the spectrometer 332.

The light source 330 may comprise a tunable light source, and it mayalso comprise a pulsed light source. A pulsed light source may have anintensity vs. time plot shown in FIG. 9B wherein light intensity 339drops off when the light is pulsed at a cutoff time τ_(cutoff).τ_(cutoff) may be less than 1 μs. FIG. 9D illustrates light pluses 343from the source 330 according to one embodiment.

In some embodiments, the apparatus of FIG. 9A may include an opticalfilter between the optical window 336 and the spectrometer 332. Forexample, as shown in FIG. 9A, a long pass optical filter 333 (e.g.λ_(cutoff)<1 μm) may be arranged in front of the spectrometer 332.Operation of the apparatus arrangement of FIG. 9A may result in a plotlike the one shown in FIG. 9C. As shown in FIG. 9C, activation of thelight source 330 results in an excitation light spike 341. Theexcitation light is turned off or pulsed, and fluorescent light from thesample 328 (FIG. 9A) continues to be detected by the spectrometer 332(FIG. 9A), but fluorescence transmission to the spectrometer 332 (FIG.9A) may be limited by the long pass filter 333. The apparatus of FIG. 9Amay be used according to principles described herein to generatefluorescence measurements and help characterize or identify downholesamples.

In some cases, 2D fluorescence measurements may be important tofacilitate downhole fluids characterization when transmissionmeasurements fail. Transmission measurements generally do not work, forexample, with emulsions. In heavy oil reservoirs drilled with waterbased muds, fluid mapping is problematic because of the formation ofstable water-in-oil (W/O) emulsions. Stable W/O emulsions addsignificant complexity to sample acquisition and may preclude standarddownhole fluid analysis measurements. However, the inventors discoveredthat fluorescence measurements yield signals that are dependent on oiltype but independent of the state of emulsion (even at very high waterfractions). Thus, downhole fluorescence measurements can be used toperform hydrocarbon fluid mapping in the reservoir according toprinciples described herein. According to one aspect, one can perform 2Dfluorescence mapping to emulsions.

A long wavelength absorption edge for most crude oils results frompolycyclic aromatic hydrocarbons (PAH). The coloration is linearlydependent on the concentration of these chromophores in accord withBeers law:

$\begin{matrix}{A = {{{- \log}\frac{I}{I_{O}}} = {\sum\limits_{i}\;{ɛ_{i}c_{i}1}}}} & (1)\end{matrix}$where: A is absorption,

-   Io the incident light intensity,-   I the transmitted light intensity,-   ε_(i) is the molar extinction coefficient for component i, and-   c_(i) is the concentration of component i and l is the path length.

The equation for the fluorescence intensity for solutions undergoingdiffusional fluorescence quenching is obtained from analysis of theexcited state decay rate:k _(F) =k _(Fo) +[Q]k _(Q)  (2)where: k_(F) is the excited state decay rate and the measuredfluorescence decay rate,

-   k_(Fo) is the intrinsic fluorescence decay rate in the absence of    quenchers,-   [Q] is the quencher concentration, and-   k_(Q) is the diffusional quenching rate constant which is diffusion    limited.

The Stern-Volmer equation is obtained from Eq. 2:

$\begin{matrix}{{\frac{I_{Fo}}{I_{F}} - 1} = {\frac{k_{Q}}{k_{Fo}}\lbrack Q\rbrack}} & (3)\end{matrix}$Equation 3 shows that, for I_(Fo)>>I_(F) (which applies for crude oils),the fluorescence intensity for a concentrated sample is proportional tothe quencher concentration. The quenchers are the large PAHs that havered shifted electronic transitions, i.e., the same molecular fractionsthat give rise to crude oil coloration.

It can be shown that to the zeroth order, both crude oil coloration(Eq. 1) and crude oil fluorescence intensity (Eq. 3) are linearlydependent on the population of large PAH chromophores. Thus, for a givencrude oil, one can quantitatively relate coloration and fluorescenceintensity (FIG. 10).

For the same reasons described above, one discovers correlations betweenthe absorption cutoff and or fluorescence intensity and fractions whichinclude large PAH molecules. FIG. 11 shows an example of suchcorrelations with asphaltenes+resin fraction. FIG. 12 shows anotherexample of a correlation between absorption cutoff (fluorescenceintensity) and C36+ weight fraction, respectively.

The plots comprising FIGS. 10-12 include oils from many differentgeographic regions. It is expected that these correlations willstrengthen when the data are restricted to a single basin. It is alsoexpected that these correlations will further improve when the data arerestricted to a single zone where compositional gradients are due toprocesses such as biodegradation. Other correlations may be discoveredby those of ordinary skill in the art having the benefit of thisdisclosure with routine experimentation following the principlesdescribed herein, such as between absorption cutoff (fluorescenceintensity) and density or viscosity.

FIG. 13 displays 2D fluorescence contour plots for twenty-nine differentdead oils from many different geographic regions, and Table 1 providesassociated “SARA” analysis. As known to those of ordinary skill in theart having the benefit of this disclosure, SARA analysis is a method forcharacterization of heavy oils based on fractionation, whereby a heavyoil sample is separated into smaller quantities or fractions, with eachfraction having a different composition. Fractionation is based on thesolubility of hydrocarbon components in various solvents used in thistest. Each fraction comprises a solubility class containing a range ofdifferent molecular-weight species. In this method, the crude oil isfractionated to four solubility classes, referred to collectively asSARA: saturates, aromatics, resins, and asphaltenes. Saturates aregenerally iso- and cyclo-paraffins, while aromatics, resins, andasphaltenes form a continuum of molecules with increasing molecularweight, aromaticity, and heteroatom contents. Asphaltenes may alsocontain metals such as nickel and vanadium. The SARA method is sometimesreferred to as Asphaltene/Wax/Hydrate Deposition analysis.

TABLE 1 sample saturate aromatic resin asphaltene 24 96.2 3.7 0.1 0 2186.1 13 0.9 0 2 61.3 34.5 4.2 0 14 72.8 21.8 5.1 0.3 17 72.7 20.8 6.4 010 67.1 24.9 7.9 0 3 67.1 24.6 8.3 0 20 51.2 38.7 10 0.1 1 60.8 28.9 9.80.4 19 63.1 26.7 10.1 0.1 6 60.8 28.6 10.5 0 8 50.1 38 11.7 0.2 15 63.624 12 0.4 18 59.4 26.9 13.6 0.1 22 59.1 26.8 13.1 1 32 59.6 26.1 13.70.7 28 60.8 24.5 14.2 0.5 7 61.2 22.7 15.4 0.6 12 52.6 31.3 15.2 0.9 955.5 27.1 15 2.5 13 45.9 33.9 17.3 3 5 52.1 27.2 16.1 4.9 27 48.7 29.419 3.1 25 46.7 30.2 18.8 4.5 29 45.6 31 19.1 4.6 16 53.4 22.8 17.7 6.630 45.1 30.4 19.6 5.1 31 47 27.3 18.7 7.6 23 45.6 28.5 19.8 6.5 26 43.230.8 20.2 6.2 4 38.3 35.3 18.5 8.6 11 37.9 32.4 18.3 12.9

There appears to be no simple linear correlation with SARA analysisbecause of the distortion that self-absorption induces in thedistributions. However, when fluorescence maps of oils from a singleregion are carefully examined, they may provide a sensitive fingerprintthat can be correlated empirically with oil properties. Also, a 2Dfluorescence map can be advantageously sliced at different energies andthe strength of any correlations (e.g. density, C36+, asphaltene/resin,weight fraction) may depend on a specific excitation/emissioncombination, as shown in FIG. 14.

The preceding description has been presented only to illustrate anddescribe certain embodiment and aspects. It is not intended to beexhaustive or to limit the invention to any precise form disclosed. Manymodifications and variations are possible in light of the aboveteaching. Moreover, the principles described herein are applicable todrilling and measurement operations, production logging, permanentmonitoring, well services for injected fluid, etc.

The embodiments and aspects were chosen and described in order to bestexplain the principles of the invention and its practical application.The preceding description is intended to enable others skilled in theart to best utilize the principles described herein in variousembodiments and with various modifications as are suited to theparticular use contemplated. It is intended that the scope of theinvention be defined by the following claims.

1. A method, comprising: downhole fluid mapping, the downhole fluidmapping comprising: providing a downhole testing tool, wherein thedownhole testing tool comprises a downhole detector with a pulsed bluesemiconductor light source; deploying the testing tool into a borehole;measuring fluorescence downhole; correlating fluorescence measurementswith oil properties, wherein the oil properties comprise fluorescentrelaxation times measured downhole by the pulsed blue semiconductorlight source.
 2. A method according to claim 1, wherein the downholefluid mapping occurs in the presence of water-in-oil emulsions.
 3. Amethod according to claim 1, wherein the correlating comprises plottingwave-number versus fluorescence intensity.
 4. A method according toclaim 3, further comprising generating a correlation function based onthe plot.
 5. A method according to claim 4, further comprising matchingthe correlation function to a correlation function for a known oil.
 6. Amethod according to claim 1, wherein the fluorescence measurementscomprise 2D fluorescence measurements.
 7. A method according to claim 6,wherein the fluorescence measurements comprise a 2D fluorescence map,and further comprising slicing the 2D fluorescence map at differentenergy levels to find a correlation between fluorescence and oilproperties.
 8. A method according to claim 1, wherein the correlatingcomprises plotting asphaltenes and/or resins weight fraction versusfluorescence intensity.
 9. A method according to claim 8, furthercomprising generating a correlation function based on the plot.
 10. Amethod according to claim 9, further comprising matching the correlationfunction to a known oil.
 11. A method according to claim 1, wherein thecorrelating comprises plotting C36+ content versus fluorescenceintensity.
 12. A method according to claim 11, further comprisinggenerating a correlation function based on the plot.
 13. A methodaccording to claim 12, further comprising matching the correlationfunction to a known oil.
 14. A method according to claim 1, wherein thepulsed blue semiconductor light source is a pulsed blue LED lightsource.
 15. A method, comprising: downhole fluid mapping, the downholefluid mapping comprising: providing a downhole testing tool, wherein thedownhole testing tool comprises a downhole detector with a pulsed bluesemiconductor light source having a cutoff time less than 1 μs;deploying the testing tool into a borehole; measuring 2D fluorescencedownhole; measuring fluorescent relaxation times downhole; plottingwave-number versus fluorescence intensity; plotting wave-number versusfluorescent relaxation times; plotting asphaltenes and/or resins weightfraction versus fluorescence intensity; plotting C36+ content versusfluorescence intensity; generating correlation functions based on theplots; matching the correlation functions to a known oil.
 16. A methodaccording to claim 15, wherein the 2D fluorescence measurements comprisea 2D fluorescence map, and further comprising slicing the 2Dfluorescence map at different energy levels to find stronger correlationfunctions.
 17. A method, comprising: fingerprinting oils with anemulsion from a particular basin, the fingerprinting comprising: taking2D fluorescence measurements downhole by a downhole detector with apulsed blue semiconductor light source having a cutoff time less than 1μs; plotting the 2D fluorescence measurements versus at least one oilproperty; generating a correlation function between the 2D fluorescencemeasurements and the at least one oil property, wherein the at least oneoil property comprises fluorescent relaxation times measured by thepulsed blue semiconductor light source.
 18. A method according to claim17, further comprising generating 2D fluorescence contour plots.
 19. Amethod according to claim 17, wherein the at least one oil propertycomprises a plurality of oil properties.
 20. A method according to claim19, wherein the plurality of oil properties comprises wave number,asphaltenes and/or resin weight fraction, and C36+ content.
 21. A methodaccording to claim 17, wherein the plotting and generating compriseslicing a 2D fluorescence map at different energy levels to findstronger correlation functions.
 22. A downhole apparatus, comprising: adownhole lab module, the downhole lab module comprising: a sample flowline; a sample cell in fluid communication with the sample flow line,the sample cell comprising at least one optical window; a light sourceadjacent to the sample cell, wherein the light source comprises a pulsedblue semiconductor light source having a cutoff lime less than 1 μs; aspectrometer for detecting fluorescence; a set of instructions, that,when executed, perform multi-dimensional fluorescence spectrummeasurements downhole and correlate fluorescence measurements with oilproperties, excite an energy state of formation fluids adjacent to theoptical window above a ground state, measure fluorescence light emittedby the formation fluids in a fluorescent relaxation process from anexcited state to the ground state, plot fluorescence spectra as afunction of times, wherein the pulsed blue semiconductor light sourceilluminates a stable water-in-oil emulsion.